Demand Side Units in the SEM SEMO September 2013 - Provide and understanding how how DSUs work in the SEM

Independent Demand Site The SEM DSU Generators SEM Supply Companies Generators bid into SEM and provide generation to the pool Supply Companies purchase from pool (Suppliers) Supply Customers purchase from supply companies, or directly from the pool if setup as Trading Site Supply Unit (TSSU) Payments flow opposite direction DSUs are classed as generators in the market, and bid in prices and quantities for demand reduction + availability Supply Customers Independent Demand Site

Determining Market Schedule & Price Price = € 50/MWh Out of Merit Not Scheduled ?Dispatched? In Merit Scheduled - ?Dispatched? Determining Price Bids for each trading period (1/2 hour period) ordered from least cost to highest cost Price Takers (mainly wind) generally scheduled first as ‘no cost’ Demand determined which identifies the units (including DSUs) that are the most economically efficient to schedule : FROM A MARKET POINT OF VIEW Note: this is an unconstrained solution with no account of transmission constraints, reserve requirements etc. Bid price of marginal unit (ie. Unit that meets the last MW of demand) sets the price. Units that are cheaper than the marginal unit are in merit and scheduled IN THE MARKET Units that are more expensive than the marginal unit are out of merit and not scheduled IN THE MARKET Whether the unit is actual dispatched in the “real world” is dependent on the SO requirements at the time ie system security and constraints Price Takers (Zero Price, mainly wind) Demand 3 Copyright © EirGrid/SONI 2013

Scheduled vs Dispatched Relates to Market only The most economic dispatch No system constraints considered Dispatched Relates to System Operation (SO) SO provide a dispatch instruction in real time to the DSU Accounts for system constraints and security of supply (reserve, transmission and trips) Difference between scheduled and dispatched. Important concept for later

DSUs in the SEM Demand Side Units (DSU) must be registered in the Single Electricity Market (SEM) The DSU will submit Commercial Offer and Technical Offer data on a daily basis Payments for capacity, energy and constraints are processed through the SEM.

DSU Market Configurations Third Party – Trading Site Retail Supplier 1 Demand Reduction Capability DSU TSSU Trading Site Supply Unit DR Load DSU can either be associated with the Demand Site directly, or as part of an separate TSSU where the demand site enters into an agreement to provide a demand reduction to the DSU who then provides this offering to the market (this arrangement is known as a aggregator DSU). DSU (and associated TSSU where appropriate) must be registered in the SEM Load SU Retail Supplier 2

DSU Incentives in the SEM Capacity Payments - based on demand reduction availability - not on whether actually called upon Pot of ~ €500 million per year must be paid out Payment per trading period varies based on ‘value’ of capacity Looking at capacity payments (which are the main revenue stream) Payments are given for each ½ hour of every day (assuming availability) Payments vary significantly for a given trading period - from zero to EUR181. Final capacity price based on ‘value’ of capacity ie. Margin, LOLP etc., although the total pot per month must remain the same More examples of how capacity payment changes with trading period, month and trading day provide in the appendices – for 2012 values.

Capacity Payment Example Availability Period Demand Reduction Offered Capacity Payments per Annum#1 9am to 7pm every day 1 MW ~€42,700 24 hours per day ~€62,400 Notes: #1 – based on 2012 Capacity Payment Generator Price (CPGP) values which are a close approximation to Capacity Payments

DSU Incentives in the SEM Avoided market charges - For Demand Sites associated with the DSU, when demand reduction dispatched - Avoids the following charges System Marginal Price (SMP) ~ € 60/MWh #1 Capacity Charge ~ € 14.50/MWh #1 Imperfections Charge € 4.71/MWh #2 Variable MO Charge € 0.698/MWh #2 #1 Illustrative values only, based on approximate averages #2 Based on 2012/2013 Regulatory Authorities approved tariffs Incentives from Supplier point of view: Demand Site can avail of charge reduction (Imperfections, VMOC, FMOC, & capacity charges which all relate to procurement of energy through the SEM) SMP: but remember, still incur cost of generation to replace demand drawn from market Capacity Charge: Paid by suppliers to cover capacity payments to generators Imperfections Charge: covers Dispatch Balancing Costs, Make Whole Payments and Energy Imbalance Charges Variable MO Charge: to cover costs of running the market SMP, Cap Charge, Imperfections and VMOC are all defined as “avoided costs” in the later presentation slides. Capacity Charges paid by Suppliers used to pay Capacity Payments to the DSU Imperfections includes dispatch balancing costs i.e.. constraint charges, also energy imbalances etc.

Constraint Payments Ensures DSU is not disadvantaged when either: Scheduled in the market but not dispatched, or Dispatched by the SO, but not scheduled in Market Similar mechanism to all other generators in the SEM Should not be considered an incentive for participation, just made to ensure DSU is not disadvantaged This should not be a driver for setting up the DSU, it is to compensate for where dispatch differs from the market schedule only. This mechanism is the same for all generators in the SEM – with DSUs classed as generators too. Eg. Not scheduled, but dispatched. Paid for cost of dispatch at bid price (not market price). No real gain to DSU for this, aside from ‘Avoided Charges’ from SEm

Summary of Incentives Net Revenues#1 Capacity Payment#2 ~€42,700 9am to 7pm every day 24hr per day Capacity Payment#2 ~€42,700 ~€62,400 Avoided Charges#3 ~€0 Constraints#4 Notes: #1 – Net Revenues = Payments less cost of Demand Reduction (ie. Bid price) #2 – Based on CPGP for 2012 #3 – Assumes not dispatched by SO due to typically higher bid price #4 – Payments at bid price only

DSU Obligations in the SEM Submission of Commercial and Technical Offer Data - needed daily (bids, shutdown cost, forecast availability, forecast minimum output, forecast, min stable generation, ramp rates and down times) - conform to Bidding Code of Practice Settlement - Check and reconcile settlement with bids, demand reduction and availability Invoice Payment - DSUs invoiced separately - Payments due to market for: Fixed Market Operator Charge (€ 100 per year per MW capacity) Resettlement - 3 working day payment terms, otherwise default and possible suspension Credit Cover and Management of Credit Cover - minimum credit cover required ~ € 5000

Demand Site Supplier Unit Avoided Charges Payments in the SEM Scenario Scheduled in Market Dispatched by TSO A1  A2  A3 A4 DSU Revenue Demand Site Supplier Unit Avoided Charges  Cap#1 Cap  Cap #1 Most Likely Scenario Scenarios are for DSU with no demand associated with TSSU Most likely scenarios are: A1 and A3 – ie. Scheduled and Dispatched (cost effective), not schedule and not dispatched (not cost effective) In the first two scenarios the DSU is scheduled in the market as it is in merit order (ie. cheap enough). Scenario A1: (second most likely scenario) First scenario it is also dispatched. In this case DSU receives Cap payment, demand site supply unit avoids the costs (imperfections, capacity charges, MOC) for the demand reduction quantity Scenario A2: DSU receives cap payment, no avoided charges for demand site supplier unit as demand reduction not activated Scenario 3 and 4 – not scheduled in market as not cheap enough. Scenario A3: (most likely scenario) Not scheduled and not dispatched DSU gets capacity payment for availability only. No avoided charges by Demand site supplier unit as no demand reduction Scenario B4: Not scheduled but dispatched for system reasons (security of supply etc) DSU receives capacity payment Demand site supplier unit has avoided costs (imperfections, capacity charges, MOC) for the demand reduction quantity Notes: #1–DSU will not receive capacity payments for Demand Reduction that is netted against TSSU for DSU Trading site

Example A1: One Trading Day - Scheduled and Dispatched DSU Bid Bid Price € 600.00 /MWh Demand Reduction Offered 1 MW Available between 9am and 7pm Market Prices* SMP Averages (excluding 5pm to 7pm) € 59.36 /MWh SMP (5pm to 7pm) € 600.00 /MWh Capacity Payment Price (Average 9am to 7pm) € 11.67 /MWh Related Charges* Capacity Charges Price (Average 5pm to 7pm) ~ € 22.09/MWh Other Charges € 5.40 /MWh *based on 2012 Trading Period averages. See Appendix B for full details Market Outcome 1 MW demand reduction:-Scheduled in market : 5pm to 7pm Dispatched by TSO : 5pm to 7pm for DSU Capacity Payments (Paid by SEM)   € 116.72 = Capacity Payment x DSU Reduction x duration One advantage of DSU as opposed to WPDRS is that you can declare availability for any date or time (assuming you can comply), not just for the WPDRS season. Also you are paid for availability more so than being called on. Note: if you have a Retail Supply agreement for the demand site then the contract you have may be based on a different tariff and not pass through charges as defined here. Assumptions: DSU Available for 1MW from 9am to 7pm Scheduled and Dispatched for 1MW from 5pm to 7pm DSU is marginal unit (ie. Last to be schedule in merit order as highest cost) Capacity Payment Prices based on 2012 Averages per Trading Period Capacity Charge Prices based on 2012 Averages per Trading Period SMP based on 2012 Averages per Trading Period (except for 5pm to 7pm period) TSSU has no demand. Therefore, no netting occurs. Market Operator and Imperfections Charge assumed to be €5.40/MWh Prices used are for example purposes only, prices change significantly due to a number of factors include availability, demand, seasonality, capacity pot size etc. Supplier Avoided Costs   € 54.99 = Related Charges x Demand Reduction Offered x duration Overall Savings (per Day)   € 171.70 Assumptions: DSU Trading Site Supply Unit has no demand, hence, no netting occurs DSU is marginal unit (ie. Last to be scheduled in merit order as highest cost)

Example A3: One Trading Day - Not Scheduled and Not Dispatched DSU Bid Bid Price € 150/MWh Demand Reduction Offered 1 MW Available between 9am and 7pm Market Prices* SMP Averages (entire day) € 63.19 /MWh Capacity Payment Price (Average 9am to 7pm) € 11.67 /MWh Related Charges* Capacity Charges Price (Average 5pm to 7pm) ~ € 22.09 /MWh Other Charges € 5.40 /MWh *based on 2012 Trading Period averages. See Appendix B for full details Market Outcome Not Scheduled Not Dispatched DSU Capacity Payments (Paid by SEM)   € 116.72 = Capacity Payment x DSU Reduction x duration One advantage of DSU is that can declare availability for any date or time (assuming you can comply) Also you are paid for availability more so than being called on. Assumptions: DSU Available for 1MW from 9am to 7pm Not Scheduled and Not Dispatched Capacity Payment Prices based on 2012 Averages per Trading Period Capacity Charge Prices based on 2012 Averages per Trading Period SMP based on 2012 Averages per Trading Period TSSU has no demand. Therefore, no netting occurs. Market Operator and Imperfections Charge assumed to be €5.40/MWh Prices used are for example purposes only, prices change significantly due to a number of factors include availability, demand, seasonality, capacity pot size etc. Supplier Avoided Costs   € 0 = Related Charges x Demand Reduction x duration Overall Savings (per Day)   € 116.72 Assumptions: DSU Trading Site Supply Unit has no demand, hence, no netting occurs DSU is marginal unit (ie. Last to be scheduled in merit order as highest cost)

Registering a DSU#1 in the SEM ( 1 of 3) Two parts: Party registration; and Unit registration Party Registration requirements include: Accession Deeds x2 Completed Application Form Accession Fee €1284.12 Party registration may only be needed if not already a Party in the SEM and want to become DSU Party and Unit Applications are separate (but can be concurrent) To Register for Accession to the Market as a Party to The Trading and Settlement Code and the framework agreement the following must be submitted: Two copies of the Accession Deed signed by two company directors or a company director and a company secretary. Please note if party based in ROI a company stamp or seal is also required A completed application form - All application details should be compliant with your Licence Accession Fee – current fee details available at www.sem-o.com SEMO Customer Service will notify you of your Party Registration Status and on completion you will be sent a certified copy of your executed Accession Deed #1 – Details are relevant for registering a DSU in the SEM. Demand reduction being contracted to an Aggregator DSU does not require any interaction with the SEM, only with the Aggregator

Registering a DSU in the SEM (2 of 3) Unit Registration requirements include: Registering Party must hold an electricity supply licence Completed Participation Notice Participation Fee €3210.30 Evidence of SO agreements Connection Agreement extracts Proof of TUoS Forecast for Credit Cover Bank Account Details Unit Registration Data including Technical Offer Data Again only need if want to setup an individual DSU yourself. In order for a party to participate in the Pool in respect of any unit, a party must register that unit in accordance with the T&SC. In order to complete unit registration a completed registration pack must be submitted consisting of A Completed Participation Notice Participation Fee - current fee details available at www.sem-o.com Unit Registration Spreadsheet – This is unique to the unit type, select the relevant spreadsheet only, either Interconnector, Generator or Supplier Finance Spreadsheet – For Banking and VAT details Collateral Spreadsheet – This is an estimate of the Market Participants forecast demand for the initial exposure period. To enable credit cover calculations to be performed Note: There is currently an outstanding issue with the granting of supply licences for DSUs in Northern Island, this is being worked through by the NIAUR.

Registering a DSU in the SEM (3 of 3) Application must be submitted at least 60 working days in advance of proposed effective date Technical testing is required to interface to Market System Credit Cover must be in place 5 work days before effective date. A final meeting will take place with SEMO, MDP , SO and Participant to make sure all registration requirements are in place and to agree a Final Effective Date. Commencement Notice issued only once registration requirements complete No Payments for units prior to Commencement Date Start early – the process can take up to 60 days or more due to need to align setup for Meter Data Providers, System Operators, SEMO SEMO Customer Services manages all applicants through the process. SEMO liaises with the appropriate System Operators and Meter Data Providers. When an effective date has been agreed with all parties, SEMO will issue a Commencement Notice. From that date onwards the unit registered can trade in the market. Each of the steps in the registration process are interactive and dependant on the actions of the two parties to the registration process: The Market Operator and the Applicant Credit Cover based on example of TSSU, DSU and Netting Gen Unit = ~1k + 5k + 1k =€7k. This is not a charge but collateral held against payments

Contact Details SEMO may be contacted on: markethelpdesk@sem-o.com Phone NI: 0800 0778 111 ROI:1800 778 111

Document Disclaimer Every care and precaution is taken to ensure the accuracy of the information provided herein but such information is provided without warranties express, implied or otherwise howsoever arising and EirGrid plc and SONI Limited to the fullest extent permitted by law shall not be liable for any inaccuracies, errors, omissions or misleading information contained herein.

Appendix A – Capacity Prices Further examples of how capacity payments differ per day, season and trading period.

Appendix B Example A1: One Trading Day Scheduled and Dispatched

Example A1: One Trading Day - Scheduled and Dispatched

Example A3: One Trading Day Not Scheduled & Not Dispatched Appendix C Example A3: One Trading Day Not Scheduled & Not Dispatched

Example A3: One Trading Day - Not Scheduled & Not Dispatched